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Executives

Ross Craft – President and CEO

Steve Smart – EVP and CFO

Qingming Yang – EVP, Business Development and Geosciences

Curtis Henderson – General Counsel

Megan Hays – Manager of Investor Relations

Analysts

Leo Mariani – RBC

Irene Haas – Wunderlich Securities

Welles Fitzpatrick – Johnson Rice

Mario Barraza – Tuohy Brothers

Joe Allman – J.P. Morgan Securities Inc.

Kim Pacanovsky – MLV & Company

Gordon Douthat - Wells Fargo Securities

Ipsit Mohanty - Bank of America-Merrill Lynch

Mike Kelly - Global Hunters Securities

Louis Baltimore - Macquarie Capital

Daren Oddenino - C.K. Cooper

Approach Resources Inc. (AREX) Q3 2012 Earnings Conference Call November 6, 2012 11:00 AM ET

Operator

Good morning, everyone, and welcome to the Approach Resources Third Quarter 2012 Earnings Conference Call and Audio Webcast. Today’s call is being recorded. At this time, all participants are in listen-only mode. We will conduct a question-and-answer session at the end of today’s conference.

Management’s remarks today will include forward-looking statements. These statements are subject to many factors that could cause actual results to differ materially from management’s expectations as expressed in those forward-looking statements. Those factors are described in the company’s SEC filings and management refers you to the company’s website or to the SEC’s website to review those filings.

The company undertakes no obligation to publicly update or revise any forward-looking statements. During the call, management will refer to certain non-GAAP financial measures. Reconciliations of these measures are provided in the Third quarter 2012 earnings release and have been posted to the company’s website under the non-GAAP financial information page at www.approachresources.com.

Also a new presentation has been posted to the company’s website and is accessible from the homepage. Now, I am going to turn the call over to Ross Craft, Approach’s President and CEO. Please proceed Sir.

Ross Craft

Thank and good morning to everyone. With me on the call today we have Steve Smart, Chief Financial Officer; Qingming Yang, Executive VP, Business Development and Geosciences; Curtis Henderson, General Counsel; and Megan Hays, our Manager of Investor Relations.

This quarter demonstrates both the opportunities and the challenges we had in transforming Approach to the drill bit from a natural gas dominated economy to a significant oil producer in the Wolfcamp shale. We believe that Wolfcamp shale is potentially one of the best on-shore oil plays in North America.

A year ago, our production was made up of 19% oil. This quarter, our oil production was up 113% and made up 34% of our total production. In addition, total production increased 22% year-over-year to 8.1000 BOEs per day despite mechanical issues, with a third party 20 inch natural gas line as well as a processing facility being fed by this line.

We estimate the impact of our third quarter production from plant down time was approximately 340 BOEs per day. The down time primarily affected our North and North Western Pangea area, with a majority of our horizontal drilling to date has taken place. We have moved quickly to address the transportation of processing issues and have completed construction of a 5.5 mile 8 inch high pressure gas gathering system that services our north, central and Eastern Pangea area. We have begun construction of a 3.1 mile 8 inch high pressure gathering system servicing northwestern Pangea area.

We anticipate having this line in service by the third week of November. Once the 3.1 mile system is completed, 100% of our wet gas will move south under the same transportation and processing agreement that is currently in place for our Pangea West, our Northeast Pangea and Southeast Pangea areas.

In addition to significantly reducing future downtime as a result of the construction of the two gathering systems, contract netbacks for residue gas and NGL buy ins will increase by 2%. Ethane and Propane recoveries will increase by 5% and line loss and fuel will decrease by 2%. A map of the new lines of processing facilities is on slide 9 of our presentation.

With that I’m going to turn it over to Steve to review the financial results and then he’s going to turn it back and I’m going to go over some operation results with you.

Steve Smart

Okay. Thanks, Ross. Revenues for the third quarter 2012 totaled $33 million which was a 19% increase compared to the third quarter 2011 revenues of $28 million. Revenues for the third quarter 2012 were supported by higher production volumes, but offset by lower than anticipated NGL and gas price realizations.

Our average realized price for the third quarter 2012, before the effect of commodity derivatives was $44.21 per BOE compared to $45.70 per BOE for the prior year quarter. Our average realized price for third quarter of 2012, including the effective commodity derivatives, was $44.78 per BOE compared to $47.98 per BOE from the prior year quarter.

Net loss for the third quarter was $2.4 million or $0.07. This compares the net income for the third quarter of 2011 of $7.1 million or $0.25 per diluted share. Net loss for third quarter 2012 included an unrealized loss on commodity derivatives of $4.2 million. Excluding the unrealized loss on commodity derivatives and related income tax effect, adjusted net income was $387,000 or $0.01 per diluted share.

EBITDAX for the third quarter 2012 was $21.4 million or $0.63 per share compared to $21.7 million or $0.76 per share in the third quarter 2011. Total expenses trended higher in third quarter of 2012 which all set increases in our production. Lease operating expense for the third quarter was $8.24 per BOE. Operating expense rose due to increases in compressor rental and repair, well repairs, workovers and maintenance and water hauling and insurance.

Severance and production taxes were up this quarter due to an increase in oil, NGL and gas sales. Severance and production taxes per BOE however were lower this quarter at $2.21 per BOE or 5% of all NGL and gas sales.

General administrative expenses were $7.56 per BOE, and increased primarily due to higher personnel costs associated with increased staffing and an increase in share-based compensation.

D&A for the third quarter was $22.39 per BOE. DD&A increased primarily due to higher production and increased investment in the Wolfcamp shale play relative to the estimated proved developed reserves.

Capital expenditures for third quarter totaled $77.1 million and included $60.3 million for drilling and completions, $11.7 million for pipeline and infrastructure projects, $4.4 for acreage acquisitions and $738,000 for 3D seismic data.

We increased our outlook for 2012 capital expenditures to $290 million. The increase reflects additional infrastructure projects of approximately $16.6 million, drilling completion costs of approximately $12.2 million, acreage acquisitions of $5 million and 3D seismic data costs of approximately $1.2 million. At September 30th 2012, we had $47.6 million in debt outstanding and $323 million of liquidity.

The equity offering in September improved liquidity and put us in a strong position to accelerate the horizontal development of the Wolfcamp oil shale play in 2013. In addition, our borrowing base was increased to $280 million from $270 million. Including the borrowing base increase, our liquidity position at September 30th was $233 million.

We’ve provided our current hedge position in the earnings release. During the third quarter we added to our oil derivative positions with a crude oil collar for 350 barrels per day for September 2012 through year-end at a contract price at 90 by 100 and 230 collar per barrel.

We also added a crude oil collar covering 450 barrels per day for 2013 at a contract price of 90 by 100 and 145 per barrel. Lastly, we added 2 natural gas swaps for 2013 covering a total of 390,000 MMBtu per month at a weighted average price of $3.67 per MMBtu.

Now, with that I’ll turn it back to Ross.

Ross Craft

Thanks, Steve. We completed several bit horizontal Wolfcamp wells during the quarter. The University 45 C 806CH well targeted the WolfCamp B bench and was completed with 30 stages. The 806H well flowed initial 24 hr rate of 922 BOEs per day made up of 93% oil.

Also the University 45 D 905H well started in the Wolfcamp A bench was completed with 34 stages. The 905H well flowed initial 24 hour rate of 689 BOEs per day made up of 90% oil. This rate reflects a 44% improvement over the average rate for our first two horizontal A bench pilot wells. We also recently completed the University 45 G 2217 H and the university 45 G 2216H. Each well targeted the WolfCamp B bench and was completed with 20 stages. The 2217H is flowing at 627 BOEs per day made up of 84% oil with approximately 8% fluid recovery at this point.

We still have a lot of load to recover in both these wells. The 2216H is flowing back. It’s in the same early stage flow back characteristics, about 8% fluid recovery at this point. These wells have continued to increase in their oil production rate daily. Overall, we remain excited about the WolfCamp play.

On slide 16 in our presentation, we show production data for nearly all of our wells we’ve driven the play to date, compared to horizontal well type curve. These wells are tracking our type curve very nicely. As part of our transformation of the asset base, we’re investing a significant amount of our capital program on the infrastructure projects that we believe will contribute to our operations for years to come.

These expenditures include capital for frac water supply wells, disposal wells, water transportation and treating systems, gas lift infrastructure in Pangea west, north and northwestern Pangea. As can be seen on slide 8 of our company presentation, one these infrastructure projects are operational D&C costs as well as LOE will be significantly reduced.

In addition to the above projects, we have begun construction of our oil gathering and transportation and sales systems. This system should be in place by the second quarter of 2013 resulting in reduced transportation differentials as well as improved movement in sales of our oil production.

We’re focused on reducing our operating expenses and improve capital efficiencies. We believe we’ll start to see the benefits of the infrastructure projects gathering lines and pipelines during the first quarter of 2013. Between now and year-end, we expect to bring eight horizontal wells on production during the quarter. As a result, we believe we’ll have a strong momentum as we head in 2013.

That concludes our prepared comments. Thank you for participating. Let’s open it up for Q&A

Question-and-Answer Session

Operator

(Operator instructions). Please standby for your first question which comes from the line of Leo Mariani from RBC. Please do go ahead Leo.

Leo Mariani – RBC

Hey guys. Just trying to get a sense of when that third horizontal rig is going to show up here?

Ross Craft

Yeah. Leo, right now we have it scheduled to come in either at the last week of December or the first couple of weeks of January, 2013. That’s our timeframe at this point.

Leo Mariani – RBC

Okay, that’s helpful. And I guess, could you talk about the A bench in a little bit more detail. It looks like generally speaking the production rates there have been a little bit lower than the B bench. What are your thoughts on quality of the A bench versus the B now that you’ve got several wells now.

Ross Craft

Yeah. We’re very excited about the A bench well. Our wells were drilled. If you look at them, especially on the two first wells, initial wells in Pangea west, what we were doing is we’re mixing up and backwards engineering surfactants trying to get a better flow back. But a lower decline rate flow back as well. As you can see from our scatter plot in our presentation where we’ve projected every data point on every well we’ve drilled except the first three, as you can see those A bench wells, although they started out with a reduced IP, if you look at how they’re projected out on the type curve, they’re actually above our type curve projections at this point in time. Lower decline rates, the surfactants that we reengineered on it appears to be working on them. We also made some modifications on the third well which was the 905 well. We added a breaker to that well. That actually helped us even more on the plow back. We had higher rates on that and so when you look at the characteristics of these wells and look at the climb rate as projected in our type curves in the presentation, these wells are performing right in line with what we thought. Yeah, the IP is a little bit reduced on them, but as I’ve been telling everybody for a long time IPs don’t really mean a whole lot to me. When I look at decline rates and look at where it stacks on top of the type curve, I’m extremely excited about the A bench.

Leo Mariani – RBC

Okay, that’s helpful. And I guess could you just give us some color in terms of where those first two A bench wells in Pangea west are producing here today?

Ross Craft

The A bench wells right now I think they’re somewhere around the high threes or low 400 BOEs range. They fluctuate back and forth. They really haven’t declined a whole lot from what they originally started at. So they’re still hanging in there very nicely.

Leo Mariani – RBC

Okay. And I guess when are you all planning on doing C bench tests?

Ross Craft

Originally we would have liked to get a C bench test in the fourth quarter, but right now the key to all this is let’s get this infrastructure programs in place. These infrastructure programs that we have right now in place, yeah that’s a significant amount of money we’re spending but what’s that going to do, that’s going to set us up for full development mode, reduce well costs, reduce LOE costs. So with that and we got sidetracked a little bit by having to build these two gas gathering systems that we hadn’t anticipated building at this point. Probably it’s going to be the first quarter, second quarter 2012. Once we get these systems in place then we’ll crank up and start C bench and full development, especially with that third rig coming in. that will allow us more flexibility on drilling the C bench wells.

Leo Mariani – RBC

Okay. And I guess could you just address current low costs today in terms of what you’re seeing your last few wells in the Wolfcamp?

Ross Craft

Yeah. Well costs are turning downward as we have mentioned before. One thing to point out that when you look at the projected horizontal well costs that we’re looking at for the whole year and you look at the number of wells taking all the science out of these wells such as the micro size, such as the logs that we’re running, such as the seismic and everything else that we’re doing on the side of these wells and look at what the trending cost is. It’s about 6.7 average of 20 wells for the year. Remember, the first part of the year we didn’t realize any of the frac reduction cost. It was still very high cost a well for still early on $7 million wells at that point. But what we’re seeing right now is that well costs are turning to the 6.5 to 6.3 as we said in the third quarter. you won’t see the big reduction in well cost till this infrastructure program is in place. That’s why it’s so critical to get this infrastructure program installed and online right now because that’s where we see the true impact and we see the true reduction in cost of these horizontal wells bringing us down to our targeted cost of $5.5 per well. And that’s the key to this play. Well results are well within line of what we expected. I was very, very pleased when we – on our scatter plot if you look at it and our 450 MBOE type curve. We’re right in line. If you look actually as we’ve told you all before, we have wells that are going to do quite a bit better than the 415 and we have wells going to do somewhat underneath the 450. But statistically I think our 450 curve is right in line and I’m very pleased with the results and how these wells are holding in there as compared to the original projections.

Leo Mariani – RBC

Okay. So it would be fair to say that your first quarter of ’13 well costs should be down pretty materially? That’s really the quarter end, we’ll see the results show up?

Ross Craft

Yeah. It all depends on when we complete the infrastructure program. We’re about probably a month and a half behind because we had to pull equipment off to build that 5.5 mile gas gathering system and that 3.1 mile system .and so the 3.1 mile system should be operational by the third week of November. At that point we’ll redeploy the crews, the pipeline crews that we have on that system back in the infrastructure. Assuming no weather delays and the remainder of second half of November and first part of December, hopefully we’ll have the infrastructure program completed by the first quarter of 2013 of which you’ll start seeing some savings in 2013 the first quarter, but you won’t really start seeing the full impact probably till the second quarter.

Leo Mariani – RBC

Okay. Thanks guys.

Operator

Your next question comes from the line of Irene Haas from Wunderlich Securities. Please go ahead Irene.

Irene Haas – Wunderlich Securities

I have actually two questions for you. Firstly, the gathering line that you’re building right now so it was a bit of a surprise. So once you’re done, would you still have the option to go, aside from DCP, would you still have an option to actually sell your gas into WTG? Is it mutually exclusive? And after that has been completed, are you pretty much iron clad with most of the things that can surprise you on the infrastructure side? That’s question number one. Question number two is simply your natural gas liquid mix percent ethane, propane and then C4 and higher as such. And that’s all I have.

Ross Craft

All right Irene, thanks. The gathering lines, yeah. By installing gathering lines we didn’t take away the tie-ins going to WTG. Those tie-ins are still in existence. So we have the flexibility whenever we want to, to either go north with our gas or go south with our gas. Although the processing facility and the upgrades we’ll receive by going south is good. When you look at that, what’s happening out there and it’s really a high class problem we’re having. This 20 inch system that goes to the west that feeds the WTG facility is overloaded because of the success of the Wolfcamp drilling in this area. Their line pressure is maxed out. We’re at the tail of the line and that’s really a good problem to have. It shows that the wells throughout the area are producing and doing quite nice. When we go south and that was the original plan if you recall the WTG contract was scheduled to expire at the end of November at which time we were going to either, they were going to re-up at a higher percent of proceeds or they were going to discontinue it. They chose to discontinue it, but we encouraged them to discontinue it earlier than the contractual terms because of the downtime.

We don’t see a solution to the downtime on the WTG system anytime soon just based on the amount of activity in the area. We’re going south. The benefits of going south, you’ve got plants that have plenty of room in them. You don’t have the congestion in the supply lines going to the plants, going south. You get a better net back, POP net back, 2% increase in that. You get a 5% increase in methane recoveries. You get a 5% increase in propane recoveries. You get a 2% reduction in fuel and line loss. All that is increasing our net backs.

So we’re going to be staying, going to the south for some time now and we’re really excited about it. The downtime is going to be reduced to just a minimal amount. We finished 5.5 mile line, the 5.5 system. we’re flowing gas. As of Monday we’re flowing gas down that system. If we can speed up the 3.1 mile system hopefully we’ll have operational before the third week, but if everything goes kind of as we have projected it won’t be any later than third week of November when that system will be on and then 100% of our gas will be heading south.

So we’re pretty excited about it. As far as the liquid makeup of the NGLs, when you look at this combined stream, the Btu values of this combined stream of the Wolfcamp gas is going to be somewhere, anywhere from 1300 on a dry basis. 1330 up to 1370 on a drier basis. The breakout of ethane is about 42% to 45% ethane depending on the Btu value for that particular area. The propane value is going to make up about 33% to 25% and then is going to be split pretty evenly with the remaining portions of it. So it’s a good high class problem to have. It’s very rich gas, throws off a ton of NGLs. And so that’s kind of how the makeup of the gas stream looks.

Irene Haas – Wunderlich Securities

No, this is really helpful. And really to follow up, would you have any guidance for the NGL price realization because this quarter undoubtedly has been or third quarter has been impacted. And so I’m just really looking forward to first quarter when everything is up and running. What would that number be?

Ross Craft

We haven’t issued any guidance yet on any of the numbers and what we want to do is wait to see when the systems are installed, wait to see what the true impact of it. So when we give you a number it’s not going to change. I’m not happy with the third quarter results. I’m really not, but you have to understand though, what we’re doing now and spending this capital on now is for the long term. This program as of the beginning of 2012 we were still delineating the field. We were still learning about the completion process. We were proving it up. To spend this kind of money we’re spending on the infrastructure we wouldn’t be spending it unless the field was working perfectly and really if you look at the statistical plots in our presentation, the scatter plots, you can see just how reliable these wells are and how close to our type curve they’re working.

So I anticipate once we get our reserves knocked out and we update on the location counts, we update on well costs, we update on the systems in place plus we have our ore pipeline in place then at that point I think we can give you a lot better color on all the parameters at that point.

Irene Haas – Wunderlich Securities

So you plan to do the year-end reserves along with all the guidance in January?

Ross Craft

We’re working on the year-end reserves and depending on when we get those flanged up we should have the guidance for you at the early part of January or somewhere around that point when we come out with our fourth quarter numbers and hopefully I’ll have the results for you at that point too.

Analyst

Okay, great. Thank you.

Operator

Your next question comes from the line of Welles Fitzpatrick from Johnson Rice. Please go ahead

Welles Fitzpatrick – Johnson Rice

Morning?

Ross Craft

Hey Wells. How are you doing man?

Welles Fitzpatrick – Johnson Rice

Good. The 1003H and 6507H, were those two wells using the reduced chemical mix that the three prior wells that came on around 500 barrels a day had been?

Ross Craft

Yeah. Those two wells actually were kind of a hybrid. What we did on those two wells, we didn’t run a breaker with those two wells. Our surfactants – we were still playing with surfactants as in the previous wells we had mentioned. But we had refined it somewhat. But we didn’t run a breaker and now what we’re running is kind of more in line with what you’ve seen before although I’ve tweaked it a little bit. We’re using hydrogen peroxide as the breaker agent. Its’ a natural oxidizer. It works very nicely and then we’re seeing the benefit I believe of the breakers. It does reduce the amount of damage created by your friction-reducing agent. It does create headaches when you’re trying to pump these jobs because we are basically running a slick system all the way through, but yeah, there was a difference between those two wells and the latter two wells that we mentioned. Also we changed the perforations.

We went back to our old way of perforating which is basically four clusters. Limited entry, 40 to 45 shots in four clusters. We believe that we’re getting a more uniform breakage of the rock at the existing rates we’re finding. We were doing eight clusters prior to that and I think we just weren’t getting the efficient rock breakage that we wanted to see. So we switched back. So for right now on the go forward we have our chemicals pretty much lined up. We’re still tweaking the surfactants a little bit. We’re reverse engineering surfactants as I said earlier, trying to give us a more uniform plow back with a flatter decline. We’re trying to copy some work that was done in the Barnett combo on reverse engineering surfactants and it looks like it’s working well. So it’s still in motion. But we’re pretty much back to where we used to be.

Welles Fitzpatrick – Johnson Rice

Okay. And this third for the year done prior to those that came on, that kind of 500 level. Have they held up?

Ross Craft

They’ve held up pretty well. They didn’t come on with a high IP, but the decline rate has been less than what we originally had modeled. And so it does indicate that the IP rate, you really can’t put much credit in the IP rate, but the decline rate is well within range of our statistical scatter plot. It’s moving nicely and matching the data points nicely.

Welles Fitzpatrick – Johnson Rice

Okay. And one more if I can get it in. can you give us your thoughts and obviously you haven’t put out guidance in regards to this, but your thoughts on ’13 LOE. It seemed like the bump quarter over quarter, some of that was quasi one time. Do you think ’13 is going to fall more in line with the front or the back half of this year?

Ross Craft

Well, that’s a very good question. Obviously as we progress through in changing from a gas company to a more oil dominated company, our cost per BOE is going to go up, there’s no question about it. It’s got to. These wells cost more to operate. But what you saw in the third quarter and probably the fourth quarter coming up too, you’re going to see a higher cost in it because these infrastructure programs are not in place yet. When you look at the big changes as Steve mentioned, saltwater disposal is a big, big issue with these wells. You’re disposing a lot of water. All these wells and this water is very expensive to haul and dispose. And so that’s one of the increases.

Also R&M increases for workovers jumped in the third quarter. we think that number will tell in the fourth, but still that’s part of it. But I would hope that we see a substantial reduction in LOE with these infrastructure programs, especially when you think about the gas lift systems and the fact that we will no longer have to rent wellhead compression. It will be operating off our main compression system that we’re already paying for. Obviously if you can do that you’ll cut the fuel consumption off by about 30MCF per well per day. That’s what these units are burning which will drive up our prices and our volumes. You’ll also reduce that $5,000 to $4,500 a month per well in compression charges. So that’s going to help you. You’re going to keep these wells on gas lift for much longer than anticipated because that’s the most cheap. That’s the most efficient use of any type of artificial lift for this type of well, obviously also frac water. We’ve drilled a series of Santa Rosa wells.

Our goal by the first of the year is to have all of our frac water being sourced by our Santa Rosa wells and that’s one thing that in our CapEx numbers we didn’t anticipate early on is to drill all these Santa Rosa well. They cost about $200,000 a pop to drill. They’ll come in around 4,000 barrels a day of Santa Rosa water. That water is perfect for fracking with. We have to treat it. We have cleaned up a little bit, but it’s no major issue. And then the infrastructure of transferring water from well site to well site without using trucks. That’s a big saving. Trucking out here is very expensive. And so all this combined should reduce the LOE considerably. As far as to quantify that, let’s get the systems in and we can see. But you can do at the back of the envelope just on disposal water. We’re going to cut $4.50 a barrel off of disposal water and if you look at the projections, in 2013, first of 2013 we’re going to be producing close to 100,000 barrels per month of water. And so that’s a pretty significant savings on that as well.

Welles Fitzpatrick – Johnson Rice

All right, perfect. Thanks so much.

Operator

Your next question comes from Mario Barraza from Tuohy Brothers. Please go ahead Mario.

Mario Barraza – Tuohy Brothers

Most of my questions have been answered. Can you talk a little bit more about how it’s taking you to drill a horizontal well today and where you see that heading next year?

Ross Craft

Yeah. We’ve just set the internal records for drilling. The last two wells we drilled we did it in record time, close to 12 days spud to TD and that’s drilling 15,000 feet of measured depths. As I said earlier in our previous discussions, drilling cost is fixed for the most part. There’s not a lot you can do to change your impact, your total drilling cost, just your drilling side of it, even by shaving another two days, yeah you might knock 50,000 off of it. But its’ not going to affect you that much. Our goal is to obviously get it down in the eight day range. We’ll do that by bringing spud rigs in and setting the surface pipe with spud rigs before we can bring the expensive rig in. And so we should be able to shave a couple more days off. But for the most part I’m very satisfied with the drilling times. My drilling department has done a fabulous job of going from 30 days initially back when we first started down to 12 days now and we’re projecting to hit eight days in the future.

And it just shows you what you can do once you get the play figured out and once you start looking at it from a manufacturing process and that’s what you have to do here. So yeah, the drilling times are coming down. I don’t think we can get much below eight days. That’s a pretty good time. Completion costs are coming down obviously. I don’t think they’re coming down as much as they did the first half of the year, but they’re coming down a little bit. There’s ways we can improve that, although not significantly. The big cost reduction in the cost of these wells is going to come from the infrastructure, water handling on the frac water, saltwater disposal, gas lift, things like that.

Mario Barraza – Tuohy Brothers

Okay. And you’re certain that’s all going to be a first quarter event next year?

Ross Craft

That’s what we have it projected assuming we don’t get sidetracked with weather, any major weather events out there. We should have a lot of the systems in place in our horizontal area by the first quarter.

Mario Barraza – Tuohy Brothers

Okay. Thanks a lot.

Operator

Thank you for your question. Before we pop our next question we would like to all analysts that they limit their questions to two each just in the interest of time. Your next question comes from the line of Joe Allman from J.P. Morgan. Please go ahead Joe.

Joe Allman – J.P. Morgan Securities Inc.

Thank you. So why are the rules changing all of a sudden on me?

Ross Craft

Hey Joe, we’ll give you flexibility there.

Joe Allman – J.P. Morgan Securities Inc.

Okay, thanks. So when I look at your well results so far in the horizontal Wolfcamp, it appears that certain parts of your acreage are more productive and more oily than other parts. So for example in North and Central Pangea, the most northern and western part seems more productive than the eastern part where you’ve got the Cinco Terry wells. So would you expect future wells to be the same? In other words more productive in that northern and western part and if somewhat less productive and in fact less oily, near the Cinco Terry wells.

Ross Craft

No, not at all. Actually when you look at this statistically and that’s how you have to look at this from a statistical standpoint and if you look at all the wells combined you have – some of the wells we drill will have a higher gas content because of the fracture systems. Some of the wells will have much higher oil content. They’re scattered in between, but when you look at the overall statistical average our wells are right in line with – depending, it doesn’t matter they’re on the east side or on the west side, they’re right in line with what we thought. Now if you look at just IP rate, you can make that conclusion, but if you look at long term rates, 30 day rates, 60 day rates, 90 day rates, 120 day rates, these wells are all responding very similarly in nature, especially if you refer back to the scatter plot in our presentation. You can make an argument that our type curve is too low. You can make an argument that the wells are performing better than our type curve. But statistically, and this is how you have to look at this, you look at the whole card. We do not see any variabilities between the east side, the west side, the north side. We don’t see it. We see variabilities from well to well. You can drill a well right next to each other and you’ll have slightly different well results. But for the most part our results as compared to neighbors to the North are all well within line. So I really can’t make a comment about is one area better than the other one because in our opinion we think it’s all good.

Joe Allman – J.P. Morgan Securities Inc.

That’s true also with oil cut too? Because when I look at the map, I look at your wells on the east side, the 1001H, they have a 60% oil, the 2101H it was 42% oil, the 701H is 51% oil, then the one you just announced yesterday, the 1003H 70% oil. It just seems that there’s a concentration of lower oil cut wells on that east side.

Ross Craft

You can look at individual wells and look at that and you can probably draw a conclusion, but I can also point to 83% oil in the same area. I can point to 81%, 97% in the same areas. Looking at the individual wells and then spreading them out and looking at them from a group wells, we don’t see a lot of difference in them. As I said you’re going to get variabilities between wells, but as far as the most part you should look at this as everything is going to be in line with what we’re saying about our 450 type curve with the oil percentage being around 58% for the long term on these wells. And natural gas is going to be 20% and NGL is going to comprise of 23% plus or minus.

Joe Allman – J.P. Morgan Securities Inc.

Okay. So if I hear you correctly, so there’s nothing about the acreage and your results so far that would indicate to you that you’re going to see significant differences throughout – in different parts of your acreage position?

Ross Craft

No. You can even go back and look at the slide on 14 in our presentation and even go up to the north, 60 miles to our north and you’ll see variabilities in those wells as well. You’ll see one at 80%, one at 75%. You can go up and look at the acreage between us. That’s 84% on 14 wells as posted. So when you look at it across the board, you’re going to see some variability, but when you look at it as a statistical model, it fits nicely in statistical modeling.

Joe Allman – J.P. Morgan Securities Inc.

Okay. So related to the A bench wells, I know you have only three A bench wells at this point and the first two ha an initial production rate lower than the average of your B bench wells, but the decline appears to be shallower. And so how about with this third, this most recent one, it has a higher production rate. I know it’s an earlier well. Is the decline on this one also relatively shallow compared to the first A bench wells?

Ross Craft

That’s correct and this gets back to the surfactants and reverse engineering the surfactants. If you look at - in how the surfactants work on these well, you can run a high volatile surfactant like we did in the initial wells in 2011 and early 2012 and what you see on those wells, you see some really, really nice attractive IPs, IPs that you guys like to see, the 800s, 900s, 1300s. but after 15 to 20 days, it’s going to decline down to what we see throughout statistically our wells. What we’re trying to do with these surfactants is going in and change the surfactant a little bit to lower our decline rates and I think it’s working. They did a lot of research on this in the combo, Barnett combo play and there’s been a lot of engineering work toward these surfactants. So playing with the surfactants, yeah we hope that these surfactants will continue to show the results they’re showing. The 905, although it’s early, we don’t have a lot of data on that well. But that well looks to be following in line with what we saw on the previous two A bench wells as far as decline rates.

Joe Allman – J.P. Morgan Securities Inc.

Okay, that’s helpful. And then in your release you indicated that you actually completed ten wells during the third quarter and your press release highlights only six. So what about the other four? Do you just not have the data or are those wells not so good?

Ross Craft

No. Either we talked about them already or we haven’t gotten the data back on them.

Joe Allman - JPMorgan Securities Inc

Okay. That’s helpful. Okay, and then just on the infrastructure, if you go to that slide 9. Could you just use that slide as a reference and explain in very simple terms what was the problem in the third quarter with the downtime. Like locate for us where that problem was? And then I just wanted to talk a little bit – after that, let’s talk about what exactly you are doing. I know you are building that 5.5 mile line now and then you’ll follow it with the 3.1 mile line but I see another kind of shorter half mile line as well. Can you explain what the other taps are and how that may plan any changes you are making.

Ross Craft

Good question, Joe. As we were on the WTG system that goes up to the Beniden plant, which is located in at the intersection of Reagan and Upton County, North West of us. That’s a 20 inch line, that’s an old line that feeds that plant. Historically, that line hasn’t had all this rich production in it. But that line also goes through all the activity areas where everybody is doing the drilling right now. That line is packed. It also has a pressure rating limit on the line which is a little bit lower than what normal supply lines are. Out there I believe the maximum pressure on that line is 800 pounds versus to 1,050 pounds that most lines operate. So with that being packed and with us being at the tail of that line, we are impacted a little bit more. So what happens at that point is as everybody continue to drill out here and continue to pack the line, it became evident that this problem wouldn’t -- a isolated problem as the operator would – WTG would try to tell us they would have it fixed tomorrow, they’d have it fixed the next day. It never got fixed. So at this time in time – and what we had, we had two elections. We could just sit back and go as we had been and I didn’t want to do that. So what I did, I went down and I worked a deal out with DCP. I’d lay 5.5 miles which basically ties in the – what we call the Angus system into their line. Their line goes – the blue line is the old PENTAX reverse line. It goes down South and then it goes into two of their facilities down South. They have two processing facilities in Southern Crockett and Central Crockett plus one in Sonora. These systems are about 65% utilized as far as plant capacity there’s still a lot of room in them. The pipes are not full pipes. So that’s going to allow me more flexibility on pressure. I’ll be able to maintain production at a higher rate on that because I am not fighting this continuing up and down of pressure. The 3.3 mile system which basically feeds off of our block 45 area. What we call the block 45. That system, 3.1 mile system should be installed in, some other radiant system should be installed in as I said by the third week in November at the latest. The nice thing about these two systems, we looked at it from a future perspective as well. We could have ran a lot smaller pipe but we are projecting for the future so we don’t have to add to this system, 8-inch gives us all the capacity we’ll ever need on all our systems out here. Also that little 0.5 mile Baker system is on Southern acre, we started development of horizontal wells to the Southern portion of that around that system. And so we felt like it was in a more impactive to us to go ahead and lay an independent system there. That way we have three systems we can go on. If one system goes down, we can back up with the other system. All this works out long term. It all also puts all 100% of our gas from the same contract which gives us better net backs. But that’s kind of how the system works. Instead of going to the North, we are going to the South.

Joe Allman - JPMorgan Securities Inc

So, I thought that the problem in the third quarter was a gas processing plant, but what you seem to describe was not a gas processing plant problem but a pipeline problem.

Ross Craft

It’s a combination of the two. The plant did have problems. It had some significant problems as well. But a big chunk of it was the pipe itself supplying the plant.

Joe Allman - JPMorgan Securities Inc

And which plant is it? The DCP processing plant down to the South of that map that we are looking at?

Ross Craft

No. that’s the – we are going to the old – the 20-inch that we are talking about in the processing plant that had the problem is the Beniden plant which is located to the North West of us up the intersection of Upton County and Regan county up there.

Joe Allman - JPMorgan Securities Inc

So it’s a combination of a pipeline issue and a plant problem there. And those grey kind of broken short line – I’d say those represent your current taps into that WTG line?

Ross Craft

That’s correct. Those grey represent the current taps in the WTG.

Joe Allman - JPMorgan Securities Inc

Okay. So how much of your production right now are you moving through WTG and how much are you moving through DCP right now?

Ross Craft

Right now the only thing going through WTG at this point is going to be our block 45 acreage. That’s the only thing going through it. As of Monday, we reversed and our Angus system. And so the basically Northern Pangea, Central Pangea, Eastern Pangea is going into DCP through that 5.5 mile system. So the only thing that’s left open is the block 45 system.

Joe Allman - JPMorgan Securities Inc

Okay. So block 45 is going to WTG. Everything else is going South right now?

Ross Craft

That’s correct.

Joe Allman - JPMorgan Securities Inc

Okay. But you still – but for future production you need to continue to build into these taps just to get some more of your production on line on that DCP line?

Ross Craft

Yeah. Once we finish the 3.1 mile system, we’ll have all our taps in place. We won’t need to build or having more taps.

Joe Allman - JPMorgan Securities Inc

Okay. Very good. That was more than two questions. Sorry about that.

Operator

Thank you. Your next question comes from Kim Pacanovsky, from MLV & Co. please go ahead Kim.

Kim Pacanovsky – MLV & Company

Hi, good morning everyone. Joe, that was way more than two questions.

Ross Craft

Good questions though, they were good questions.

Kim Pacanovsky – MLV & Company

They were great questions. They always are from Joe. Hi, guys. I just have a couple of very quick questions, honest. First is, when was the 450 barrel a day collar put into place that was put in place this quarter. And just curious with the transition to full development mode in 2013 and consequential increase in oil production. I am curious why you weren’t more aggressive with that hedge that was added as far as volume is concerned?

Steve Smart

We’ll, Kim I don’t know the exact date at this point on that hedge we put on the oil color but I think it would have been in August and certainly it would have been after our second quarter earnings call. And then your second question if I heard you right was about the two gas hedges we put in place.

Kim Pacanovsky – MLV & Company

No. the oil hedge. I am saying if you are really moving into full development mode in 2013 and we are going to have expected continued ramp in oil production I guess my question is why you didn’t hedge a greater quantity of oil at …

Steve Smart

We’ll, we’ve been limited to this point to a line of credit. I said like 85%. We have got that increased to 100% and we are going to continue to look for opportunities to hedge not only because our reserves report will be updated and we’ll have an increased volume of projected PDP for 2013 and beyond. That for 2014 we still have some room we can do more as well. I am just kind of watching crude right now. I like it – as you can tell, I like to have a $90 floor but we may not get that exactly. I still think it will be good even if we had an 85 floor it would be good which you can get today, but you know how crude oil is and predictability about it is going to fluctuate and you’ll get an opportunity at some point.

Kim Pacanovsky – MLV & Company

Absolutely. Okay great.

Ross Craft

Once we get our reserve report finalized. One thing we have to look at on reserve reports we have to – we can only hedge what we have booked on PDP, the percentage basis. So as we are accelerating the Wolfcamp and we are growing our reserve in PDP basis, that will automatically allow us to layer on more hedges and more hedges. So it’s kind of a balancing act. We’d like to hedge a lot more but our covenants wont let us until we actually get the reserve report finished and supply that. So we’ll be – as we increase our reserves, as we finish the reserves issues, we’ll be definitely trying to layer in a lot more oil hedges. We love layering the hedges.

Kim Pacanovsky – MLV & Company

Okay. Great. Good news. And then second question. Can you just remind us what the oil cut was in the A bench pilots. Was it as high as you reported in these two wells in this release?

Ross Craft

I think it’s around 85% something like that. Let me look. I don’t know if I have that exactly in front of me. Yeah, it’s 84% to 79% on those two well. I think you are referring to the 6601, 6602 A bench wells.

Kim Pacanovsky – MLV & Company

Alright. So I guess we are going to see kind of all over the map as we have in your B bench wells?

Ross Craft

Yeah, what you are going to see, you are going to see – we are still – if you look to the type curve that we have and the projections that we have for these wells long term, what we are looking at is somewhere around a 57%, 58% oil makeup of the 450,000 Boe. About a 22% to 23% NGL makeup and the remaining being natural gas. And that’s fitting very nicely with our type curves. Right now, it looks like we are right on target. I was very pleased when I looked at my type curve as it relates to my scatter plots. And this is all our wells with exceptions of the first three wells for the most part which were done with – we are still learning on those wells. And as you can see on slide 16 of our presentation, the data is really hanging in there nicely. More importantly, past about 120 days you watch as the data starts narrowing and as it narrows down, it’s actually slightly above our type curve. So – and when I am looking at the later time, 180 days out, 240 days out, 300 days out. Of course we don’t have so many data points out there because most of our well are newer, but the data is laying right on top of our curve which gives me a lot of comfort in that our curve is correct and there probably isn’t a need to change the curve. We like it and it gives flexibility. Remember, this statistically you are going to drill some wells and some wells and some wells are going to perform above the curves, some wells are going to perform below the curve but average we think the 450 that we gave you guys. We don’t think you are going to go wrong with that.

Kim Pacanovsky – MLV & Company

Okay. Great. Thanks. And let me just ask one more quick thing. Somebody asked before about the drilling time. But can you give us a split-to-sales time and perhaps the number of wells that you anticipate being either drilled or brought on line in 2013 with the preliminary budget that you announced today?

Ross Craft

Yeah. The spot-to-sales is – I wish I could give you a better answer than I am going to give but I am going to give you an answer. The spot-to-sales depends on a couple of things. It depends on how many wells we drill off that pad. If we elect to drill three wells off that pad, then your spot to sales could be 9 to 100 days. Our four wells of that pad. if we do two wells we are talking about 60 days. And that is because what we have to do is drill the wells, we have to frack them all at the same time and then we have to bring all at the same time back on. That’s the only way you can do it. Right now, what we are looking at doing is staggering our surface locations. For example, the North location will be drilling wells to the South, the South location will be drilling wells to the North. That would be two to three wells per pad. So let’s assume two wells per pad to answer your question. We are talking about 60 days at the high end it goes as high as 80 days depending if we have a problem. But that’s kind of what we are thinking. If you had a third well to it, what you are going to be adding is probably another – alright, I am just guessing another 20 days max. So it’s a balancing act, you don’t want to drill too many wells on one pad because you tie up too much capital without getting any production back on it. So we think we have the optimal plan. As far as the number of horizontal wells where we are going to try and achieve in 2013 is somewhere between 35 and 40 wells.

Kim Pacanovsky – MLV & Company

Great. That’s the number I need. Super. Okay, thanks a lot guys.

Operator

Thank you. Our next question comes from Gordon Douthat, from Wells Fargo. Please go ahead Gordon.

Gordon Douthat - Wells Fargo Securities

Thank you. Good morning. So just a question on down spacing. I just wanted to get your latest thoughts on how you might incorporate this program going forward and then somewhat related, as you proceed with your pilot program in the A bench and soon the C bench. How will you look to drill these wells in relation to your B bench wells where you first look to establish productivity before, maybe stacking the laterals or how are your thoughts along those lines?

Ross Craft

Good question. The down spacing obviously what we are looking at on down spacing is probably somewhere going to be around – and this is per bench well, say B bench, say 100 feet to 660 feet between B bench wells. That’s kind of the down spacing model we are using right and I don’t think we have seen any data suggested change in that going forward. Now that’s not what we’ve backed into our 500 horizontal locations that we’ve talked about for this past year. That’s a 1000 foot center between them but we think the 660 to 700 is the way to go at least at this point. How we are going to stack the laterals on the different benches, once we get confirmation on the C bench and that’s going to take another couple of wells on the C bench and by the way I don’t have any another COG press release about their C bench well but they just drilled a very nice C bench well. So I think what we are seeing on the C bench and the A bench combined, there will be more of a Chevron type of stack, they wont be directly on top of each other, they might be 300 feet offset from each other. For example, we’ll have a A bench well, 300 feet away moving either left or right, you will have a B bench well, 300 feet going back under it kind of back where the A bench well was. We shall drill a C bench well right underneath that. And that’s kind of the way we are looking at it right now. We feel like by doing that type of geometrics on these wells that we’ll maximize our rock breakage to the different fracks and so – but all of that is going to be work in progress. Obviously we’d need to do a few of these pilot programs where we stack the three laterals and we frack them, run micro size on them to see exactly how the geometrics work from the frackture systems but that is what we are envisioning at this point.

Gordon Douthat - Wells Fargo Securities

Have any of your A bench wells been in that formation in relation to the B bench wells to date?

Ross Craft

No. we haven’t and really the third rig bring us some flexibility because the third rig will allow us to put two rigs in full development mode, one in Pangea West and one in North Western and Northern Pangea with the third rig being the moving rig. It will be moving to the North East Pangea, Central Pangea, South Pangea area over in the South Western portion. So that will allow us to still be able to experiment with the third rig but we have two full developments going with the two rigs.

Gordon Douthat - Wells Fargo Securities

Okay. And then last question for me. It looks as if the lateral links are getting longer. What’s your latest thought there as far as the 7,000 foot, 8,000 foot? Where to you see in. thank you.

Ross Craft

We’ll, the only reason that we’ll drill a longer lateral than say a 7,500 foot is least geometrics. If we have a section that’s a little bit longer and to maximize coverage on it we’ll drill a little bit longer well. 8,000 foot, I don’t anticipate us drilling any and beyond that and actually our program is geared more towards a 7,600 foot to 7,500 foot lateral. What we are going to be playing with going forward is a reduction in frack stages. Obviously we think that is going to impact just as well. You look at our initial wells; they were ranged in more than 21 stages up to 24 stages. Those wells produced quite nicely. So what we are thinking about doing is starting to space our stages out a little further a part and try to reduce down from 30 stages back to 28 to 24 stages and that’s going to be one of our big focuses this first part of 2013 to nail that down and see if we can in fact reduce the number of frack stages and that’s going to be a function of hydraulics, how we perforate the stages, how we frack the stages but we think that that’s ultimately going to be part of our big plan.

Gordon Douthat - Wells Fargo Securities

Okay. And then as far as your target of well cost. What lateral links and frack stages are backed into that number?

Ross Craft

The target of well cost has a 28 stage completion in it over the lateral link of 7,500 feet.

Gordon Douthat - Wells Fargo Securities

Okay. That’s it for me. Thank you.

Operator

Thank you. Your next question comes from Jeff Hayden, from KLR Group. Please go ahead Jeff.

Adam Fackler - KLR Group

This is actually Adam Fackler on Jeff’s behalf. Most of my questions have been answered. I just was hoping you might be able to provide some color on the number of potential locations you could see the A bench adding to your horizontal inventory?

Ross Craft

Yeah, we really haven’t quantified that in writing yet. We have internal projections on the A bench and what we have said in the past and I think it’s still holds true is based on the response of the A bench pilot test we think that once you go into full development mode on the A bench. Forever B bench while you are drawing A bench well as well. Hopefully at the end of this year once we get the reserves all finalize, we’ll have some color on the actual number of A bench locations, but it’s going to be a significant improvement in the number of horizontal locations. Remember in our 500 locations that we have published in the past, there’s no A bench well as it all in us. Its two-thirds B bench and one-third C bench wells. And so you will get a significant bump up on the A bench once we incorporate that into full development.

Adam Fackler - KLR Group

Thank you very much. That’s it for me.

Operator

Thank you. Your next question comes from Ipsit Mohanty, from Bank of America-Merrill Lynch. Please go ahead.

Ipsit Mohanty - Bank of America-Merrill Lynch

Good morning guys. Additional questions beyond what’s been already asked. In terms of your 2013 cost guidance. Do you still see the same exploration targets of $4 to $5 a Boe to hold up in ’13 given how much you’ve already did this greatest parts of the play.

Ross Craft

We’ll if you look at the what goes into our exploration model. Obviously that’s seismic and any lease renewals that we have. There’s always going to be a certain percentage of lease renewals out here. And while we are just extending leases and things like that. Seismic wise, once we get past is $1.2 million investment that we are doing currently on and that’s shooting seismic across our North Eastern Pangea area which will be our final seismic shoot. We don’t anticipate having additional seismic programs ongoing in this field. We’ll have 100% coverage for the most part throughout the field and there won’t be a need for it. So I would anticipate seeing a slight reduction of exploration cost on a go forward basis.

Ipsit Mohanty - Bank of America-Merrill Lynch

Alright. Great. And just talking about going into the end of the year, sort of looking into 2013 and a very close clear view. Do you anticipate adding on the NGL hedges in ’13 as well?

Ross Craft

We would love to head on NGL hedges. Obviously NGL values are a big fortune of our wells. The problem we’ve had at this point is when you look at the markup of a barrel of NGL being Ethan predominant. Being ethane and then propane being secondary. The ethane market is no surprise has been suppressed. Propane level markets have been suppressed. We ended last year with the inventory build in propane. So until I can get to see some type of movement especially in propane and I would to see it above $1, $1.15 a gallon something like that. At that point then I’ll definitely look at locking in hedge values on propane. Ethane is going to have to recover quite some – you know when you look at ethane. The last hedge is that we booked ethane was trading at the $0.77 range, something like that. Now it’s way lower than that. Ethane is going to drag but if we can get some movement in ethane then we’ll definitely try to lock in ethane numbers.

Ipsit Mohanty - Bank of America-Merrill Lynch

Got it. And one last. Just looking into the 2013 CapEx and projecting it quarter wise, do you plan to sort of spread out the de-completion target of 10 mill or due you lump it into quarter as you did in ’12?

Ross Craft

Yeah. I wish I could give you more color on that. We really look at the exploration; I mean the re-completion program as needed basis. What we would like to do is maximize our frack equipment and so if we see a time where for example, with three rigs we are going have to be using a one and half crews, of frack crews. And so we see a need where we need to stack up some re-completions to keep the crews 100% occupied. Then we’ll do it but it’s hard to project that. I know that’s not the answer you all wanted to hear because it’s hard to model that in but I think if you just use a couple of quarters something like that, thee a quarter, I think you’ll be doing good.

Ipsit Mohanty - Bank of America-Merrill Lynch

Thank you again.

Operator

Your next question comes from the line of Mike Kelly, from Global Hunters Securities. Please go ahead Mike.

Mike Kelly - Global Hunters Securities

Good morning Ross.

Ross Craft

Hi, how are you doing?

Mike Kelly - Global Hunters Securities

Good, thank you. Given this year’s heavy infrastructure CapEx spend. I was hoping you just take a minute and take a step back and re-vist the economic benefits or rationale of this program and – because I was hoping to quantify the per well savings you would expect to achieve after you are done with this program. And if we can boil it down to a number of wells you have to drill to recoup that initial investment.

Ross Craft

Yeah. When you look at the investments that we have made and we are going to make on the water of transportation, the gas lift system, solar disposal systems. When you look at that, let’s first address it from a D&C cost perspective. What you are going to see is the average fracks we are doing are – basically we are buying 250,000 barrels of water. But that water cost to buy and to track that water in is anywhere from $2 to $3 a barrels. So when you figure that you are going to be buying 250,000 barrels and let’s say $3 a barrels and then you are going to then change it and go to your Santa Rosa self-sourcing wells, which are cost per barrel at that point going to be somewhere around $1.60. That includes the $0.81 per trading the water, getting it ready to frack and then a $0.25 operating margin on operating these wells and frack and everything else. We’ll that alone is going to be somewhere around $465,000, $450,000 savings is just on the water alone right there on the frack water. Then on the reverse side of that when you put this water in you are going to have to get it back. We’ll the way we have it set up in our models and stuff, six months – at the end of six months, and that’s when the AFPs roll off and that’s when it goes into LoE, you are going to recover about 100,000 barrels of water in the first six months, plus or minus. Water disposal is going to cost you around $5, on the average $5 a barrel for disposal and tracking. We are going to take that down to $0.50 a barrels. That savings alone on 100,000 barrels in is going to be somewhere around $450,000. So right there alone you have $900,000 in saving just on water handling, disposal and source water for fracking. Then you look at it from transportation of water. With these infrastructure programs and transporting water to a particular well site without having to use third party pumps and equipment, you are going to save about $100,000 per well because the systems are all in place. And then on the gas lift system, you are going to – when you look at that you are going to save roughly about 30McF per well for the first six months. And so the figure is about $2 an McF on savings there. And then you are also going to save the wellhead compressor that we are having to put out on each on of these wells which is anywhere from $4,500 to $5,000 a month. So you’ll see our savings there. As far as payout of the system for example, let’s take Pangea West, that’s a good one because Pangea West is pretty much done and we have an investment in Pangea West somewhere around probably $8 million I guess, plus $7 million or $8 million in that. And so if you can save a $1 million a well cost, then it’s 7 or 8 wells. And that you are going to be paying this thing off in. So it’s a really quick turnaround time especially when you are look at the amount of location that we have to drill. Remember we are looking at having the potential of having $500 million barrels equivalence under this acreage to extract. So, yeah it’s a lot of money upfront. It really is but long term it’s going to payout over and over and over. So it’s relatively short payout time on these wells. 7 or 8 wells you pay it out. And so from that stand point, I think you can understand the need for why we want to do it but not only in the D&C cost savings. The big cost is our water production, we are used to do gas wells out here. They don’t make water. They might make a barrel or two a day of water. So historically our lease operating cost per disposal has been marginal. It’s really not much and now because of these wells produce a lot of water, they are still producing the frack water back even beyond six months. You can figure a one-to-one ratio kind of what we figure our own whatever barrel of water you produce you produce a barrel, a barrel and half of water, something like that. And so now you start looking at that disposal as it relates to $5 a barrel versus $0.50 a barrels. That’s a huge savings on LoE, that could be $700,000 per month just off that saving right there alone depending on how you look at it. Then when you look at the projection of water with our drilling program in three rigs, we are going to be at the beginning of 2013, we are going to be producing somewhere around 100,000 per month of water just from three rigs. As we continue to add the rigs you are going to see another ramp of water. So water is the key. And you are seeing this a lot of in the Delaware basin as well where people are putting in systems too because that’s one of the biggest cost structures and operating these wells is disposal handing of water. This is not just unique to this; this is pretty much typical in the Permian basin area with the horizontal application in the Wolfcamp. You are seeing the same type of cost savings measures once the operator feels comfortable enough that the field is in development mode then they look at how they can substantially reduce cost and this is how you do it.

Steve Smart

So, that’s an excellent slide 8 by the way and the updated presentation. All those number Ross is talking about there.

Mike Kelly - Global Hunters Securities

Got it. Okay. Great. And that’s good color. This next question here I doubt you’ll give me nearly as much color on but just question right now in you’re a pure on the Wolfcamp in the Southern Midland basin. Just any thoughts, do you intend to stay kind of in that position or you are looking elsewhere in the Permian or outside from a leasing perspective?

Ross Craft

Yeah, that’s a good question. When you look at the evolution of our company and you look at the number of locations and just the vastness of work that we have in the – where we are right now in the Southern Midland basin. We can make a career out of just developing this. Obviously that’s not the game; the game is we’ve found this. We have brought it into full development mode for the most part. We want to find another one. That is the key in growing our company. We want to find another one of these plays. But as with any type of expansion program that you have, going out of your comfort zone, going to lets just say for example going five States North or seven States to the East, that creates a bunch of operational and efficiencies for a company of our size. So we want to stay focused in the Permian. There’s a lot of opportunities in the Permian, the Maverick basin, the Val Verde basin. There’s a lot of opportunities still out there. And so obviously we’d like to expand and if we expand I think we’ll expand in those basins for right now. Obviously what I would like to do if it was my charismas wish list, I’d like to have a very nice acquisition to tack on in 2013. Acquisition with quite a bit of production with it, that would be ideal for us. Unfortunately we haven’t been able to find any or at least haven’t been successful on pricing of it. But yeah, we definitely want to continue to look. We don’t want to just get fixated with what we have right now. We want to look to the future. We want grow this company.

Mike Kelly - Global Hunters Securities

Alright. Great. Very interesting. Thank you.

Operator

Thank you. Your next question comes from the line of Louis Baltimore, from Macquarie Capital. Please go ahead Louis.

Louis Baltimore - Macquarie Capital

Yeah, just really quickly. I was wondering I guess going forward given the shallower decline rates you’ve been targeting, and there’s kind of lower IPs. Should we expect the IPs to be in the kind of 500, 600 Boe a day range or kind of should we expect them to come back to the 900 average that we’ve been seeing in previous quarters?

Ross Craft

If you look statistically and look at our type curve. What you are looking at on our type curve is Boe ranges in the 550 to 570 range. That is kind of how our type curve works. What we’d like to see is as I tweak the surfactants even more, I’d like to see some higher IP rates, I really would. But what we are looking at and we kind of alluded to this back when we did statistical analysis of all the IP rigs in this area, did the P50, P10, P9 valuation of it that anything around 600 BOEs at that time was going to be a good well. Now looking at it and changing the surfactants, even though these wells some of them are coming back a lot slower so you don’t see the big IPs, even though they come back slower and this is very clear on the Wolfcamp type curve slide in our presentation page 16. The decline rate is much shallower. It’s a given and take, obviously I would to get the bigger the IPs, it’s good press to get big IPs, but on reserve side and reserve forecasting, it’s not that critical it’s statistical we are going drill wells that have big IP. It’s always good to fill out a 1300, 1400 Boe IP for the press but if it’s a 500, it’s still a pretty good well and it’s still tracking our type curve pretty nicely. So I think you are going to see a mixture. I think you are going to see a mixture of as you did in this press release we had some – my eight or six wells, very good well. And so it’s just going to be a mixture of wells.

Louis Baltimore - Macquarie Capital

Okay. Thank you. That’s all.

Operator

Thank you. Your next question comes from Daren Oddenino, from C.K. Cooper. Please go ahead Daren.

Daren Oddenino - C.K. Cooper

Hi gentlemen, thanks for the time in taking our questions today. Just real quick. On 2013 of the 35 to 40 wells. What do you think the breakup is between A, B and C. and then on the eight that are waiting on completion. How many are A, B and C?

Ross Craft

Yeah, on the eight waiting on completion. There are all Bs right now. We wanted to drill a couple of more C bench wells before we convert that. We want to get a little more production time on the 905 before we convert A bench into full development but we are very close on that. As far as the number of locations versus A, B and C we are going to give a lot more color on that with our fourth quarter discussions. Once we have our reserve forecast pretty much completed and we have more production history with the A bench and more production history from offset operators in the C bench, then I think you’ll see us populating. We’ll give a lot more color to you guys at that point. It’s a little bit early but I can say is as I said earlier in the discussion that the A bench, the way we are viewing the A bench, for every B bench well you are going to drill an A bench well. At least and once we get the C bench in full development mode, then you are going to see increased C bench wells. But give us a little more time and we’ll up some more color on it.

Daren Oddenino - C.K. Cooper

Okay. Thanks. That’s all I got.

Operator

Thank you. That concludes your question-and-answer session. I would now like to turn the call back over to Ross Craft for closing remarks.

Ross Craft

Hi guys. First of all great questions today. We really liked the questions that we’ve received. We like answering questions; it clears up a lot of confusion. Just remember that this play a year ago was in the early stages. We were still kind of playing with the frack design, playing with the geometrics on well’s basic and everything else. Look at the expansion of this play from all operators around us in Southern Midland basin. There’s a lot of operations going on, there’s a lot of various well results being reported. One thing to point out the well results even though it looks from a well-to-well as a big difference from a statistical realms, they are all in line. All these well results are coming back statistically. The amount percent of well, the percent of NGLs everything else it doesn’t matter if you are North of us or South of us, they are all within range for the most part. We’ve basically de-risked a big portion of this play already. We have a little more work. Yeah, I might satisfy with the quarter now, I wasn’t satisfied with the quarter but it’s part of the growing thing. Just part of what we have to do to transform into a full development mode. These costs -- and it’s kind of a weird deal because this costs we look at as we as being an engineer I am. When I am designing a system and I am looking at for futuristic growth, I am looking at water production I am looking at this. As I am starting to develop the system design and I get half way through and I go I can for another $2 million I can add and cover this area over here and still be in good shape. So the infrastructure that we are building right now. The additional cost in CapEx this year that you are seeing, this is a one-time cost for the most part. We’ll have it in place at that point then you won’t see it again. So just bare with us. Everything we are doing is for a reason. It’s setting up stage to get lower well cost, lower LoEs on all of our properties out in this area. And I think that once we have the systems in place. Once we have -- and you start seeing a realization of cost savings as we mentioned before, I think you’ll see that and kind of get a idea what our vision is and with that being said we appreciate you all being on the call. Thanks for your patience and we look forward to the next call.

Operator

Thank you for your participation in today’s conference. This concludes the presentation. You may now disconnect. Good bye.

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